1. Field of the Invention
The present disclosure relates to a device and a method for evaluating the characteristics of a subterranean formation. More specifically, the present disclosure relates to a device and method for evaluating the permeability of a hydrocarbon producing wellbore. Yet more specifically, the present disclosure concerns a device and method employing both acoustic and electro-magnetic transmission and receiving means for the evaluation of a subterranean formation.
2. Description of Related Art
Knowing certain characteristics of the subterranean formation surrounding a borehole, such as permeability, porosity, rugosity, skin factors, and other such properties can be used to estimate hydrocarbon-producing capability from these formations. Some of the more fundamental reservoir properties include permeability and relative permeability, along with porosity, fluid saturations, and formation pressure. Knowing these properties is also useful in evaluating the presence of water along with the presence of hydrocarbons.
With regard to subterranean formations, permeability is a measure of the ability to flow fluids through the material making up the formation, the material is typically rock or unconsolidated alluvial material. Permeability is generally measured in units of darcy, milli-darcy or md (1 darcy≈10−12 m2). Permeability represents the relationship between flow through a medium and physical properties of that fluid to a pressure differential experienced by the fluid when flowing through the medium. For a subterranean formation to produce liquid hydrocarbon, it should have a permeability of at least 100 md, to produce gas hydrocarbon the permeability can be lower.
A determination of formation permeability can be obtained by taking a core sample. However coring techniques have some drawbacks, such as time, expense, and inaccuracies due to sample errors and limited sample amounts. Other techniques for evaluating permeability include formation testing tools that actually penetrate the wellbore wall and draw connate formation fluid into the tool. The actual fluid as well as the amount of fluid flowing into the tool can be evaluated in order to make permeability determinations. Formation testing tools however are subject to inherent errors, such as pressure differentials between the formation and the tool that allow portions of the connate fluid to vaporize, thereby altering the fluid composition. When the original connate fluid is allowed to change phase, a determination of porosity is made more difficult. Additionally, since the tool must pierce the borehole wall, mudcake present in that wall can lodge itself in the probe tip thereby precluding the taking of a representative sample of connate fluid.